Potential Sources of Water for Use in Well Fluids or Pipeline Fluids
Non-freshwater sources of water for use in well fluids can include surface water ranging from brackish water to seawater to brine. As used herein, a brine refers to a water having at least 40,000 mg/L total dissolved solids.
Additional potential sources of water for use in well fluids can include returned water (sometimes referred to as flowback water) after the delivery and use of a well fluid in a well, unused well fluid that was formed but never introduced into a well, and produced water from a well.
Another potential source of water for use in well fluids can include push pills, that is, slugs of water that have been viscosified with a synthetic polymer or a multi-chain polysaccharide used to push fluids to clean out an oil or gas transmission pipeline located at or near the surface of the ground or seafloor.
In some cases, however, a flowback water, unused well water, or produced water can have an undesirably high viscosity due to a residual viscosity-increasing polymer, which may or may not be cross-linked, that was not completely broken in the well before flowing back. Similarly, a push pill can have an undesirably high viscosity for use in a well treatment fluid. To use such a source of water in forming another well fluid, it may be necessary to break the residual viscosity caused by the residual polymeric material.
Complicating factors exists, however, in breaking a residual polymer that may exist in such sources of water: the source of the water is usually above ground and at a temperature below 100° F., usually in the range of about 80° F. to about 100° F. It is usually much more difficult to break polymeric material at such low temperatures using conventional breakers. In addition, multi-chain polymers and synthetic polymers are usually much more difficult to break than single-chain polysaccharides. Polyacrylamides are known to have good thermal stability up to 200° F.; thus are difficult to break at low temperatures, especially below about 90° F. At least these two factors make the use of such potential sources of non-freshwater in forming another well fluid very challenging.
Water-Soluble Polymers Used in Well Fluids
Common water-soluble polymers used in well fluids include polysaccharides and synthetic polymers.
A polymer can be classified as being single chain or multi chain, based on its solution structure in aqueous liquid media. Examples of single-chain polysaccharides that are commonly used in the oilfield industry include guar, guar derivatives, and cellulose derivatives. Guar polymer, which is derived from the beans of a guar plant, is referred to chemically as a galactomannan gum. Examples of multi-chain polysaccharides include xanthan, diutan, and scleroglucan, and derivatives of any of these. Without being limited by any theory, it is currently believed that the multi-chain polysaccharides have a solution structure similar to a helix or are otherwise intertwined.
Xanthan gum (commonly referred to simply as xanthan) is a polysaccharide, derived from the bacterial coat of Xanthomonas campestris. It is produced by fermentation of glucose, sucrose, or lactose by the Xanthomonas campestris bacterium.
Diutan gum (commonly referred to simply as diutan) is another multi-chain polysaccharide that is sometimes used to increase viscosity in well fluids.
Water-soluble synthetic polymers are also used. An example of a water-soluble synthetic polymer that is commonly used in well fluids is polyacrylamide or derivative of polyacrylamide. As used herein, a “polyacrylamide” can broadly include a copolymer of polyacrylamide (including, for example, a copolymer, terpolymers, or tetrapolymer). In addition, a “polyacrylamide” can broadly include a modified or derivative of a polyacrylamide, unless the context otherwise requires. Certain polyacrylamides can be classified as multi-chain polymers. Regardless of whether multi-chain or not, however, water-soluble synthetic polymers, and polyacrylamides in particular, are known to be difficult to break.
As used herein, a “polysaccharide” can broadly include a modified or derivative polysaccharide, unless the context otherwise requires.
As used herein, “modified” or “derivative” means a compound or substance formed by a chemical process from a parent compound or substance, wherein the chemical skeleton of the parent is retained in the derivative. The chemical process preferably includes at most a few chemical reaction steps, and more preferably only one or two chemical reaction steps. As used herein, a “chemical reaction step” is a chemical reaction between two chemical reactant species to produce at least one chemically different species from the reactants (regardless of the number of transient chemical species that may be formed during the reaction). An example of a chemical step is a substitution reaction. Substitution on a polymeric material may be partial or complete. Substitution is an example of a modification or derivatization process. Substitution on a polymeric material may be partial or complete.
Well Services
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well. Such well fluids commonly include polymeric materials.
Drilling, completion, and intervention operations can include various types of treatments that are commonly performed in a wellbore or subterranean formation.
For example, a treatment for fluid-loss control can be used during any of drilling, completion, and intervention operations. During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well. Even small improvements in fluid flow can yield dramatic production results.
Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Fracturing treatments are often applied in treatment zones having poor natural permeability. Matrix treatments are often applied in treatment zones having good natural permeability to counteract damage in the near-wellbore area.
Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excessive water production. Still other types of completion or intervention treatments include, but are not limited to, damage removal, formation isolation, wellbore cleanout, scale removal, and scale control.
Water-Soluble Polymers for Suspending Particulate in a Well Fluid
A well fluid can be adapted to be a carrier fluid for particulates.
For example, during drilling, rock cuttings should be carried uphole by the drilling fluid and flowed out of the wellbore. The rock cuttings typically have specific gravity greater than 2, which is much higher than that of many drilling fluids. These high-density cuttings have a tendency to separate from water or oil very rapidly.
Hydraulic fracturing is a common stimulation treatment. The purpose of a hydraulic fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. In addition, a fracturing treatment can facilitate the flow of injected treatment fluids from the well into the formation. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Preferably, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
Gravel packing is commonly used as a sand-control method to prevent production of formation sand or other fines from a poorly consolidated subterranean formation. In this context, “fines” are tiny particles, typically having a diameter of 43 microns or smaller, that have a tendency to flow through the formation with the production of hydrocarbon. The fines have a tendency to plug small pore spaces in the formation and block the flow of oil. As all the hydrocarbon is flowing from a relatively large region around the wellbore toward a relatively small area around the wellbore, the fines have a tendency to become densely packed and screen out or plug the area immediately around the wellbore. Moreover, the fines are highly abrasive and can be damaging to pumping and oilfield other equipment and operations.
Placing a relatively larger particulate near the wellbore helps filter out the sand or fine particles and prevents them from flowing into the well with the produced fluids. The primary objective is to stabilize the formation while causing minimal impairment to well productivity.
The particulate used for this purpose is referred to as “gravel.” In the oil and gas field, and as used herein, the term “gravel” is refers to relatively large particles in the sand size classification, that is, particles ranging in diameter from about 0.1 mm up to about 2 mm. Generally, a particulate having the properties, including chemical stability, of a low-strength proppant is used in gravel packing. An example of a commonly used gravel packing material is sand having an appropriate particulate size range. For various purposes, the gravel particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like. For example, a tackifying agent can help with fines and resins can help to enhance conductivity (e.g., fluid flow) through the gravel pack.
A proppant used in fracturing or a gravel used in gravel packing may have a much different density than the carrier fluid. For example, sand has a specific gravity of about 2.7, whereas water has a specific gravity of 1.0 at Standard Laboratory Conditions of temperature and pressure. A proppant or gravel having a different density than water will tend to separate from water very rapidly.
As many well fluids are water-based, partly for the purpose of helping to suspend particulate of higher density, and for other reasons known in the art, the density of the fluid used in a well can be increased by including highly water-soluble salts in the water, such as potassium chloride. However, increasing the density of a well fluid will rarely be sufficient to match the density of the particulate.
Increasing the viscosity of a well fluid can help prevent a particulate having a different specific gravity than a surrounding phase of the fluid from quickly separating out of the fluid.
A viscosity-increasing agent can be used to increase the ability of a fluid to suspend and carry a particulate material in a well fluid. A viscosity-increasing agent can be used for other purposes, such as matrix diversion, conformance control, or friction reduction.
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents or techniques for increasing the viscosity of a fluid.
In general, because of the high volume of fracturing fluid typically used in a fracturing operation, it is desirable to efficiently increase the viscosity of fracturing fluids to the desired viscosity using as little viscosity-increasing agent as possible. In addition, relatively inexpensive materials are preferred. Being able to use only a small concentration of the viscosity-increasing agent requires a lesser amount of the viscosity-increasing agent in order to achieve the desired fluid viscosity in a large volume of fracturing fluid.
Certain kinds of polymers can be used to increase the viscosity of a fluid. In general, the purpose of using a polymer is to increase the ability of the fluid to suspend and carry a particulate material. Polymers for increasing the viscosity of a fluid are preferably soluble in the external phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
The water-soluble polymer can have an average molecular weight in the range of from about 50,000 to 20,000,000, most preferably from about 100,000 to about 4,000,000. For example, guar polymer is believed to have a molecular weight in the range of about 2 to about 4 million.
Typical water-soluble polymers used in well treatments include water-soluble polysaccharides and water-soluble synthetic polymers (e.g., polyacrylamide). The most common water-soluble polysaccharides employed in well treatments are guar and its derivatives.
Crosslinking of Polymer to Increase Viscosity of a Fluid or Form a Gel
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. A crosslinker interacts with at least two polymer molecules to form a “crosslink” between them.
If crosslinked to a sufficient extent, the polysaccharide may form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
For example, one of the most common viscosity-increasing agents used in the oil and gas industry is guar. A mixture of guar dissolved in water forms a base gel, and a suitable crosslinking agent can be added to form a much more viscous fluid, which is then called a crosslinked fluid. The viscosity of base gels of guar is typically about 20 to about 50 cp. When a base gel is crosslinked, the viscosity is increased by 2 to 100 times depending on the temperature, the type of viscosity testing equipment and method, and the type of crosslinker used.
The degree of crosslinking depends on the type of viscosity-increasing polymer used, the type of crosslinker, concentrations, temperature of the fluid, etc. Shear is usually required to mix the base gel and the crosslinking agent. Thus, the actual number of crosslinks that are possible and that actually form also depends on the shear level of the system. The exact number of crosslink sites is not well known, but it could be as few as one to about ten per polymer molecule. The number of crosslinks is believed to significantly alter fluid viscosity.
For a polymeric viscosity-increasing agent, any crosslinking agent that is suitable for crosslinking the chosen monomers or polymers may be used.
Cross-linking agents typically comprise at least one metal ion that is capable of cross-linking the viscosity-increasing agent molecules.
Some crosslinking agents form substantially permanent crosslinks with viscosity-increasing polymer molecules. Such crosslinking agents include, for example, crosslinking agents of at least one metal ion that is capable of crosslinking gelling agent polymer molecules. Examples of such crosslinking agents include, but are not limited to, zirconium compounds (such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate, zirconium oxychloride, and zirconium diisopropylamine lactate); titanium compounds (such as, for example, titanium lactate, titanium maleate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate); aluminum compounds (such as, for example, aluminum acetate, aluminum lactate, or aluminum citrate); antimony compounds; chromium compounds; iron compounds (such as, for example, iron chloride); copper compounds; zinc compounds; sodium aluminate; or a combination thereof.
Other Uses of Water-Soluble Polymers in Well Fluids, for Example, as Friction Reducers
There are other uses for a polymers in a well fluid. For example, a polymer may be used as a friction reducer.
During the drilling, completion and stimulation of subterranean wells, well fluids are often pumped through tubular structures (e.g., pipes, coiled tubing, etc.). A considerable amount of energy may be lost due to turbulence in the treatment fluid. Because of these energy losses, additional horsepower may be necessary to achieve the desired treatment. To reduce these energy losses, certain polymers (referred to herein as “friction-reducing polymers”) have been included in these treatment fluids.
Friction reducers are typically used to reduce fluid turbulence and thus save the energy which would have been otherwise lost due to fluid friction with tubular. This effectively reduces the hydraulic power demands of the particular operation. In addition, the reduced turbulence also effectively reduces the erosion effect on the tubular.
Friction reducer chemicals are regularly employed in slick water fracturing in shale gas plays, in high rate water pack (“HRWP”) treatments used to place gravel between the annular space of the formation and screen, in reducing the friction of fluids flowing down coil tubing, etc.
Suitable friction reducing polymers should reduce energy losses due to turbulence within the treatment fluid. Those of ordinary skill in the art will appreciate that the friction reducing polymer(s) included in the treatment fluid should have a molecular weight sufficient to provide a desired level of friction reduction. In general, polymers having higher molecular weights may be needed to provide a desirable level of friction reduction. By way of example, the average molecular weight of suitable friction reducing polymers may be at least about 2,500,000, as determined using intrinsic viscosities. In certain embodiments, the average molecular weight of suitable friction reducing polymers may be in the range from about 7,500,000 to about 20,000,000. Those of ordinary skill in the art will recognize that friction-reducing polymers having molecular weights outside the listed range may still provide some degree of friction reduction.
A wide variety of friction reducing polymers are available. In certain embodiments, the friction-reducing polymer may be a synthetic polymer. While several chemicals and polymeric additives can function as friction reducers, the most commonly used chemicals are polyacrylamides and polyacrylamide copolymers. Additionally, for example, the friction-reducing polymer may be an anionic polymer or a cationic polymer.
By way of example, suitable synthetic polymers may include any of a variety of monomeric units, including acrylamide, acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, N,N-dimethylacrylamide, tert-butyl acrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylic acid, acrylic acid esters, methacrylic acid esters, quaternized aminoalkyl acrylate, such as a copolymer of acrylamide and dimethylaminoethyl acrylate quaternized with benzyl chloride, and mixtures thereof.
Examples of suitable friction reducing polymers are described in: U.S. Pat. No. 6,784,141 issued Aug. 31, 2004 having for named inventors Karen L. King, David E. Mcmechan, and Jiten Chatterji entitled “Methods, Aqueous Well Treating Fluids and Friction Reducers Therefor”; U.S. Pat. No. 7,004,254 issued on Feb. 28, 2006 having for named inventors Jiten Chatterji, Karen L. King, and David E. McMechan entitled “Subterranean Treatment Fluids, Friction Reducing Copolymers, and Associated Methods”; U.S. Pat. No. 7,232,793 issued Jun. 19, 2007 having for named inventors Karen L. King, David E. McMechan; and Jiten Chatterji entitled “Water-Based Polymers for Use as Friction Reducers in Aqueous Treatment Fluids”; U.S. Pat. No. 7,271,134 issued Sep. 18, 2007 having for named inventors Karen L. King, David E. McMechan; and Jiten Chatterji entitled “Water-Based Polymers for Use as Friction Reducers in Aqueous Treatment Fluids”; each of which is incorporated herein by reference in the entirety. Combinations of suitable friction reducing polymers may also be suitable for use.
One example of a suitable anionic friction-reducing polymer is a polymer including at least acrylamide and acrylic acid monomeric units. The acrylamide and acrylic acid may be present in the polymer in any suitable concentration. An example of a suitable anionic friction reducing polymer may include at least acrylamide monomer in an amount in the range of from about 5% to about 95% and acrylic acid monomer in an amount in the range of from about 5% to about 95%. Another example of a suitable anionic friction-reducing polymer may include acrylamide in an amount in the range of from about 60% to about 90% by weight and acrylic acid in an amount in the range of from about 10% to about 40% by weight. Another example of a suitable anionic friction-reducing polymer may include acrylamide in an amount in the range of from about 80% to about 90% by weight and acrylic acid in an amount in the range of from about 10% to about 20% by weight. Yet another example of a suitable anionic friction-reducing polymer may include acrylamide in an amount of about 85% by weight and acrylic acid in an amount of about 15% by weight. As previously mentioned, one or more additional monomers may be included in the anionic friction reducing polymer including acrylamide and acrylic acid monomeric units. By way of example, the additional monomer(s) may be present in the anionic friction-reducing polymer in an amount up to about 20% by weight of the polymer.
Suitable friction-reducing polymers may be in an acid form or in a salt form. As will be appreciated, a variety of salts may be prepared, for example, by neutralizing the acid form of the acrylic acid monomer or the 2-acrylamido-2-methylpropane sulfonic acid monomer. In addition, the acid form of the polymer may be neutralized by ions present in the treatment fluid. As used herein, the term “polymer” is intended to refer to the acid form of the friction-reducing polymer, as well as its various salts.
As will be appreciated, the friction-reducing polymers suitable for use in the present technique may be prepared by any suitable technique. For example, the anionic friction-reducing polymer including acrylamide and acrylic acid may be prepared through polymerization of acrylamide and acrylic acid or through hydrolysis of polyacrylamide (e.g., partially hydrolyzed polyacrylamide). See, for example, U.S. Pat. Nos. 7,846,878 and 7,806,185, which are incorporated by reference.
Slick-Water Fracturing of Shale Formations
An example of a well treatment that may utilize a friction-reducing polymer is commonly referred to as “high-rate water fracturing” or “slick-water fracturing,” which is commonly used for fracturing of ultra-low permeable formations such as shale formations.
Ultra-low permeable formations tend to have a naturally occurring network of multiple interconnected micro-sized fractures. The fracture complexity is sometimes referred to in the art as a fracture network. Ultra-low permeable formations can be fractured to create or increase such multiple interconnected micro-sized fractures. This approach can be used to help produce gas from such an ultra-low permeable formation. According to current technology, a shale formation suitable for economic recovery as a gas reservoir is characterized by having a hydrocarbon content greater than 2% by volume gas filled porosity.
Ultra-low permeable formations are usually fractured with water-based fluids having little viscosity and that are used to suspend relatively low concentrations of proppant. The size of the proppant is sized to be appropriate for the fracture complexity of such a formation, which is much smaller than used for fracturing higher permeability formations such as sandstone or even tight gas reservoirs. The overall purpose is to increase or enhance the fracture complexity of such a formation to allow the gas to be produced. Although the fractures of the fracture network are very small compared to fractures formed in higher permeability formations, they should still be propped open.
The fracturing fluids for use in fracturing ultra-low permeability formations are water-based. One of the reasons for this is the large volumes required, and water is relatively low cost compared to oil-based fluids. Other reasons can include concern for damaging the reservoir and environmental concerns.
Fluids used for fracture treatments in gas shale reservoirs are mainly water based fluids mixed with friction reducer chemicals (slick water). Most friction reducers used in slickwater fracturing are provided as concentrated emulsions of high molecular weight polyacrylamide, which can be easily inverted to dissolve the friction reducer in water. The typical concentration of these friction reducers ranges from 0.5 to 2.0 gal/Mgal. In cases where huge volumes of such fracturing fluids are used along with several stages per well, a large amount of such friction reducer chemicals are introduced into the formation. Use of suitable chemicals that can function as breakers for these friction reducers is essential to ensure minimal formation damage due to the fracturing fluid.
Preferably, a friction-reducing polymer can be included in a well fluid in an amount equal to or less than 0.2% by weight of the water present in the well fluid. Preferably, any friction-reducing polymers are included in a concentration sufficient to reduce friction but at a lower concentration than would develop the characteristic of a gel. By way of example, the well fluid including the friction-reducing polymer would not exhibit an apparent yield point.
While the addition of a friction-reducing polymer may minimally increase the viscosity of the treatment fluids, the polymers are not included in the treatment fluids in an amount sufficient to greatly increase the viscosity. For example, if proppant is included in the treatments fluid, velocity rather than fluid viscosity generally may be relied on for proppant transport. In some embodiments, the friction-reducing polymer can be present in an amount in the range of from about 0.01% to about 0.15% by weight of the well fluid. In some embodiments, the friction-reducing polymer can be present in an amount in the range of from about 0.025% to about 0.1% by weight of the well fluid.
Generally, the treatment fluids in slick-water fracturing do not rely on viscosity for proppant transport. Where particulates (e.g., proppant, etc.) are included in the fracturing fluids, the fluids rely on at least velocity to transport the particulates to the desired location in the formation. Preferably, a friction-reducing polymer is used in an amount that is sufficient to provide the desired friction reduction without appreciably viscosifying the fluid and usually without a crosslinker. As a result, the fracturing fluids used in these high-rate water-fracturing operations generally have a lower viscosity than conventional fracturing fluids for conventional formations. In some slick-water fracturing embodiments, the treatment fluids may have a viscosity up to about 10 centipoise (“cP”). In some embodiments, the treatment fluids may have a viscosity in the range of from about 7.0 cP to about 10 cP. According to a preferred embodiment of the methods, at least the first fracturing fluid has a viscosity in the range of about 7.0 cP to about 10 cP. According to a more preferred embodiment, all of the one or more fracturing fluids used in a zone have a viscosity in the range of about 7.0 cP to about 10 cP. For the purposes of this disclosure, viscosities are measured at room temperature using a FANN™ Model 35 viscometer at 300 rpm with F1 spring.
High Rate Water Pack for Sand Control
High rate water pack (“HRWP”) technique used in sand control operation employs high pumping pressure to assist suspension and carrying of gravel to pack the formation to screen annulus. Friction reducers are often employed in such a technique to avoid high pressure within the open hole section as it can fracture the formation if the fracture pressures are exceeded. Breakers are required to act on the friction reducer chemicals in the recovered and circulated HRWP fluids prior to proper disposal.
Breaker for Water-Soluble Polymer
Reducing the viscosity of a viscosified fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of well fluids are called breakers.
No particular mechanism is necessarily implied by the term “breaking.” For example, in the case of a crosslinked viscosity-increasing agent, for example, one way to diminish the viscosity is by breaking the crosslinks. By way of another example, a breaker can reduce the molecular weight of a water-soluble polymer by cutting the long polymer chain. As the length of the polymer chain is cut, the viscosity of the fluid is reduced. This process can occur independently of any crosslinking bonds existing between polymer chains.
Breakers must be selected to meet the needs of each situation. First, it is important to understand the general performance criteria of breakers. For example, in reducing the viscosity of a fracturing fluid or gravel packing fluid to a near water-thin viscosity, the breaker must maintain a critical balance. Premature reduction of viscosity during the pumping of the treatment fluid can jeopardize the treatment. Inadequate reduction of fluid viscosity after pumping can also reduce production if the required conductivity is not obtained.
Chemical breakers used to reduce viscosity of a fluid viscosified with a viscosifying polymer, such as guar and derivatized guar polymers, used in fracturing or other subterranean applications are generally grouped into three classes: oxidizers, enzymes, and acids. All of these materials reduce the viscosity of the fluid by breaking the polymer chain. The breakers operate by cleaving the backbone of polymer either by hydrolysis of acetyl group, cleavage of glycosidic bonds, oxidative/reductive cleavage, free radical breakage or combination of these processes. A breaker should be selected based on its performance in the temperature, pH, time, and desired viscosity profile for each specific treatment.
Breaking Multi-Chain Polysaccharides More Difficult
Fluids viscosified with a multi-chain polysaccharide can be more difficult to break than fluids viscosified with a single-chain polysaccharide. In particular, there are few methods available to break the fluid viscosity of a fluid viscosified with a multi-chain polysaccharide at low temperatures (below 120° F. or 49° C.), and they suffer from various problems. For example, the use of hypochlorite poses corrosion concerns and may not provide sufficient delay of the break. The current use of persulfate requires high concentrations and high volumes at lower temperatures. The use of oxidizers such as sodium chlorite is limited to high-temperature applications and may react violently to cause a fire when reducing agents are used in the process. Enzymes do not work well on multi-chain polysaccharides such as xanthan at low temperatures.
Sodium perborate and ethyl acetoacetate (“EAA”) have been reported as being capable of breaking the viscosity of a fluid viscosified with a typical xanthan gum (“XANVIS”) down to 80° F. (27° C.). See Kelco Oilfield Group in its Technical Bulletin entitled “Breaker Applications,” revised January 2004. However, Halliburton previously reported that it was unable to break a fluid viscosified with xanthan at very low temperature using the published recipe and the publication does not provide sufficient detail to allow the user to optimize the breaker recipe for a given set of conditions. U.S. Patent Publication No. US 2008/0176770 A1, published Jul. 24, 2008, having for named inventors Michael W. Sanders, et al., which is incorporated by reference in its entirety.
A treatment fluid for use in a well can optionally comprise an activator or a retarder to, among other things, optimize the break rate provided by a breaker. Previously known examples of such activators include acid generating materials, chelated iron, copper, cobalt, and reducing sugars. Previously known examples of retarders include sodium thiosulfate, methanol, and diethylenetriamine.